steam containing hydrogen sulfide is purified and sulfur recovered by passing the steam through a reactor packed with activated carbon in the presence of a stoichiometric amount of oxygen which oxidizes the hydrogen sulfide to elemental sulfur which is adsorbed on the bed. The carbon can be recycled after the sulfur has been recovered by vacuum distillation, inert gas entrainment or solvent extraction. The process is suitable for the purification of steam from geothermal sources which may also contain other noncondensable gases.
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1. A process for purifying steam from geothermal sources containing hydrogen sulfide and a minor amount of other non-condensable gases comprising:
adding at least a stoichiometric amount of o2 to the steam containing the hydrogen sulfide; and passing the steam containing oxygen at a temperature above its saturation temperature and below about 235°C through a reactor packed with activated carbon to oxidize the hydrogen sulfide to elemental sulfur and water whereby the elemental sulfur is adsorbed on the activated carbon while the water passes through the bed with the steam, thereby purifying the steam.
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The invention described herein was made in the course of, or under, a contract with the UNITED STATES DEPARTMENT OF ENERGY.
Geothermal steam is a natural resource and is found in many areas of the earth. It has been used for power generation in some areas for many years. Use of large quantities of geothermal steam for power generation will become increasingly important in the present energy short economy. However, development of many geothermal energy sources is hindered because geothermal fluids often contain contaminants such as CO2, H2, H2 S, NH3, CH4, and N2. H2 S is not only environmentally objectionable but presents potentially serious problems of corrosion to power generating turbines and associated equipment. Corrosion of power generating equipment significantly lowers the plant operating efficiency and increases maintenance costs. To operate geothermal power plants efficiently and safely, H2 S and other corrosive and environmentally hazardous impurities of geothermal steam must be removed before the steam is used for power generation.
Previous studies for the removal of H2 S from geothermal steam have emphasized the utilization of solid metal sorbents such as zinc oxide, or other sorbents containing zinc oxide. The major difficulty with these materials is the formation of metal sulfates during oxidative regeneration, with subsequent decrepitation of sorbent beads and destruction of their sorption capacity. Some physical adsorption materials such as silica, alumina and activated carbon, although effective with H2 S in dry systems, will not preferentially absorb H2 S from steam.
The use of activated carbon to catalyze the oxidation of H2 S to elemental sulfur according to the formula: 2H2 S+O2 →2H2 O+2S is well known and has been used for many years for the purification of gas streams. Streams being treated by the oxidation process are mainly natural gas, manufactured gas, coke oven gas, carburetted water gas and synthesis gas. All of the above gas streams are low in moisture (or water vapor). To date, the removal of H2 S by the oxidation reaction from gas streams of high moisture content by the oxidation reaction has been considered as an impractical method. The main reason for drawing this conclusion is that the water vapor in gas streams to be treated is also a product of the oxidation reaction. A well-known therorem established by Le Chatelier states that when equilibrium has been reached, a change in any of the factors affecting equilibrium tends to make that reaction take place which will neutralize the effect of the change. For this reason, it has heretofore been assumed that the conditions in a geothermal gas stream containing 99% water vapor, and about 200 parts per million of H2 S are unfavorable for the oxidation reaction.
However, it has been found that, under the proper conditions, the oxidation reaction can take place even in gas streams of high moisture content such as geothermal steam. The use of activated carbon as a catalyst is necessary for enhancing the reaction rate and reducing the reaction size. Thus the invention for purifying steam containing hydrogen sulfide and recovering the sulfur consists of passing the steam through a reactor packed with activated carbon in the presence of oxygen at a temperature above the saturation temperature of the steam whereby the H2 S is oxidized to elemental sulfur which is sorbed on the surface of the carbon and remains in the reactor, thereby purifying the steam of hydrogen sulfide. The sulfur is later recovered from the reactor by various methods such as solvent extraction, vacuum distillation and inert gas or steam entrainment. The carbon, after the sulfur is removed, can then be recycled.
It is therefore one object of the invention to provide a process for removing hydrogen sulfide from steam.
It is the other object of the invention to provide a process for removing hydrogen sulfide from geothermal steam and recovering the sulfur.
These and other objects of the invention for removing hydrogen sulfide from steam may be met by passing the steam containing the hydrogen sulfide at a temperature above its saturation temperature and below about 235° C., through a reactor packed with activated carbon in the presence of at least 1.3 times the stoichiometric amount of oxygen whereby the hydrogen sulfide in the steam is oxidized to elemental sulfur, which is sorbed on the surface of the carbon packed into the reactor, and water, which passes through the reactor with the steam, thereby removing the hydrogen sulfide from the steam.
The process of this invention is suitable for the removal of H2 S contained in steam from any source. Generally H2 S concentration in steam from geothermal sources may vary from 20 to greater than about 225 ppm. The process of the invention may require additional beds of activated carbon when higher H2 S concentrations are encountered. The presence of other noncondensable gases such as CH2, H2, CO2 and NH3 was found to have no deleterious effect upon the oxidation process.
The preferred oxidation catalyst is activated carbon which may contain a small amount of metal oxide such as up to about 5 to 10 weight percent CuO or Fe2 O3. Other catalysts such as Al2 O3, TiO2 and TiS may also be used although with decreased efficiency. Activated carbon is preferred because it is readily available and inexpensive. The carbon is preferably in the shape of pellets to minimize the pressure drop of the steam as it passes through the bed.
It is necessary to add oxygen to the steam as it passes through the catalyst bed in order to promote the oxidation of the H2 S to elemental sulfur and water. The amount of oxygen, which may be added as either pure oxygen or as air, may range from about 1.3 to 1.6, preferably 1.5 times the stoichiometric amount. Too little oxygen may result in some of the H2 S not being oxidized while too much oxygen may result in converting some of the H2 S to oxygenated sulfur compounds such as SO2 and SO3 which will remain in the steam. Furthermore, excess oxygen in the treated steam may cause corrosion of the power generation equipment.
In order to prevent binding of active catalyst sites by moisture, it is necessary that the steam be superheated, that is, that the temperature of the steam be from 3° to 6°C above its saturation temperature. When the process is operated above 235°C, entrainment of sulfur from the catalyst by the heated steam becomes significant and may be detrimental to the equipment; therefore, the steam temperature or the reactor temperature must be controlled under 235°C To remove H2 S from a wet steam, the steam may be adiabatically throttled or isobarically superheated with a heat source such as an electrical or oil burning furnace to form superheated steam before it is contacted with the bed of activated carbon.
Regeneration of the spent catalyst and recovery of the sulfur can be accomplished by solvent extraction, vacuum distillation and inert gas entrainment. The lesser energy is required for the solvent extraction. Preferred extractants are carbon disulfide, an aqueous solution of about 15% ammonium sulfide and dichloroethane. The extracted sulfur can be recovered by evaporating the extracted solution to separate solid sulfur and pure solvent or by chilling the extracted solution to a temperature where the sulfur which is excess to the amount which can be dissolved in the solvent at that temperature is precipitated from the extracted solution. Solid sulfur recovered by the aforesaid methods is a by-product of the process, and the solvent after being separated from the solid sulfur can be reused. The sulfur can also be thermally distilled from the sulfur laden activated carbon under a vacuum condition and recovered as a liquid sulfur in a condenser. The other sulfur recovery method is accomplished by purging hot inert gas through the bed of sulfur laden activated charcoal, thus the sulfur is vaporized and entrained by the hot inert gas to a condenser where sulfur vapor is condensed and recovered in form of liquid.
To demonstrate the process, various experiments were conducted using simulated geothermal steam (175°C and 100 psig) with H2 S concentration of 250-200 ppm. Three types of activated carbons, carbon with CuO impregnated, plain coconut charcoal, and a regenerated carbon were used. The results are given in Table I below.
The pressure of the steam as it contacted the carbon was found to have no effect upon the process of the invention. Space velocities of steam through the carbon bed may range up to about 300 v/v/min with velocities up to about 200 being preferred.
| TABLE I |
| __________________________________________________________________________ |
| RUN 70 75 77 78 |
| G-32J G-32J |
| ACTIVATED ACTIVATED REGENERATED |
| CARBON CARBON COCOANUT SORBENT |
| SORBENT +CuO (5%) +CuO (5%) CHARCOAL OF RUN 75 |
| __________________________________________________________________________ |
| WT OF SORBENT |
| 88g 85g 85g 86g |
| TOTAL RUN TIME |
| 10.5 hrs 11.25 hrs 17.31 hrs |
| 11.21 hrs |
| STEAM RATE 76.8 ml/min |
| 91 ml/min 80 ml/min |
| 74.5 ml/min |
| (AS WATER) |
| SPACE VELOCITY |
| 107/min 132/min 116/min 107/min |
| AIR FLOW RATE |
| 200 ml/min |
| 200 ml/min |
| 98 ml/min |
| -- |
| OXYGEN 42 ml/min 42 ml/min 20 ml/min |
| 98 ml/min, 40 ml/min, |
| 25 ml/min, 11 ml/min |
| H2 S/O2 |
| 1/3 1/3 1/1.4 1/6.8, 1/2.8, 1/1.7, |
| 1/0.75 |
| INLET H2 S CONC. |
| 164.7 211 185 153 |
| ppm |
| OUTLET H2 S |
| 0 TO 8 HRS |
| 0 TO 9.5 HRS |
| MOST OF TIME |
| MOST OF TIME |
| CONC. ppm <20 ppm AFTER |
| <20 ppm AFTER |
| <15 ppm <15 ppm |
| 8 HRS → 38 ppm |
| 9.5 HRS → 42 ppm |
| ACTIVATED 4.5 g. 5.3% |
| 6.8 g. 8.0% |
| 8.2 g. 9.6% |
| NOT AVAILABLE |
| CARBON WT |
| INCREASE |
| __________________________________________________________________________ |
The results of these runs show that more than 90 percent H2 O removal has been accomplished, i.e. a decrease of 250 ppm H2 S to lower the 25 ppm H2 S. Activity of the catalyst does not reduce significantly in the first few regeneration cycles. For catalyst regeneration and sulfur recovery, CS2 was used. Crystalline sulfur has been recovered by the CS2 extraction method.
A number of additional runs were made following the procedure of Example I to show the operability of the process for removing H2 S from steam. The results are given in Table II below. Note that the results generally show better than 97% sulfur removal.
| TABLE II |
| __________________________________________________________________________ |
| Run No. 124 126 127 128 129 131 |
| Activated |
| Cocoanut |
| Cocoanut Regenerated |
| Activated Carbon Charcoal |
| Charcoal |
| Activated Activated |
| Carbon from |
| Impregnated |
| Activated |
| Activated |
| Carbon from |
| Carbon from |
| Bituminous |
| With about |
| With High- |
| With High- |
| Bituminous |
| Bituminous |
| Catalyst Coal + CuO (5%) |
| 3 w/o Fe2 O3 |
| Temp. Steam |
| Temp. Steam |
| Coal + CuO (5%) |
| Coal + CuO |
| __________________________________________________________________________ |
| (5%) |
| Wt. of Cat. gm |
| 80 80 80 80 80 78.8 |
| Bed Volume, Cm3 |
| 128.8 114.1 143.5 164.9 131.7 132.5 |
| Steam Rate, |
| 20.2 20.5 20.6 20.8 21.0 20.8 |
| gm/cm2 /min |
| Space Velocity, |
| 184.6 211.1 168.9 148.4 186.6 184.4 |
| /min |
| Residence Time, |
| 0.325 0.284 0.355 0.404 0.322 0.325 |
| Sec |
| Air Rate, 50 50 50 50 50 50 |
| ml/min |
| Oxygen 1.59 1.57 1.71 1.49 1.47 1.55 |
| Stoichiometric |
| Average 3.26 2.98 4.4 11.8 2.68 1.27 |
| Outlet, ppm |
| Outlet Oxygen |
| 57.5 54.7 62.2 52.9 47.6 51.9 |
| Conc., ppm |
| % H2 S Removed |
| 98.4 98.5 97.5 94.3 98.7 99.4 |
| % Sulfur Recovery |
| 61.9 77.9 80.3 87.99 64.62 69.39 |
| __________________________________________________________________________ |
As can be seen from the preceding discussion and examples, the process of this invention provides an effective and economical method for the removal of hydrogen sulfide from geothermal steam so that a highly purified steam is available for utilization in power generation equipment without resulting in excessive equipment corrosion.
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